QEP Resources, Inc. (NYSE:QEP) (QEP or the Company) today reported
first quarter 2018 financial and operating results.
- Delivered record net oil equivalent production in the Permian
Basin of 30.9 Mboed, including record oil production of 24.0
Mbod
- Reported net gas equivalent production of 286.0 MMcfed in
Haynesville/Cotton Valley, a 110% year-over-year increase
- Increased 2018 production guidance and forecasted capital
expenditures to reflect an accelerated well delivery cadence in the
Permian Basin resulting from significant improvements in drilling
and completion efficiency
- Opened data rooms for the divestiture of the Company’s
Williston and Uinta basin assets
- Commenced execution of an authorized $1.25 billion share
repurchase program
"During the first quarter we delivered strong production growth
in the Permian Basin, driven by the continued success of our
'tank-style' completions and operational efficiency gains in both
drilling and completion activities," commented Chuck Stanley,
Chairman, President and CEO of QEP. "We accelerated the well
delivery cadence in the Permian through faster drill times and a
step-change in the number of frac stages completed each month by
each of our two completion crews. As a direct result of these
efficiencies, we were able to put 31 net wells on production during
the quarter in the Permian Basin, compared to our original plan of
18 net wells. We now expect to complete and put on production nine
more net wells than originally forecasted during 2018, resulting in
an increase in Permian oil volumes and an associated increase in
capital expenditures."
"As we continue to focus on balancing capital investments and
cash flow, we have reduced capital allocated to our Williston Basin
and Haynesville/Cotton Valley assets for the remainder of 2018 to
support additional investment in the Permian Basin. We have
delineated and refined our tank-style completion methodology over
the past year and are now in full development mode on our Permian
assets, giving us confidence in our ability to deliver the results
set forth in our revised guidance."
"We also made great progress on our strategic and financial
initiatives (Strategic Initiatives) announced in February, which
will result in QEP becoming a pure-play Permian
Basin company. Data rooms for the Williston and Uinta basin
assets are open and we expect to have these asset sales completed
during the second half of 2018. We also began executing our share
repurchase program by opportunistically repurchasing over 6.2
million shares of common stock in March," concluded Stanley.
The Company has posted to its website www.qepres.com a
presentation that supplements the information provided in this
release.
QEP First Quarter 2018 Financial Results
The Company reported a net loss of $53.6 million, or $0.22 per
diluted share, for the first quarter 2018 compared with net income
of $76.9 million, or $0.32 per diluted share, for the first quarter
2017.
Net income or loss includes non-cash gains and losses associated
with the change in the fair value of derivative instruments, gains
and losses from asset sales, asset impairments and certain other
items. Excluding these items, the Company’s first quarter 2018
Adjusted Net Loss (a non-GAAP measure) was $47.9 million, or $0.20
per diluted share, compared with Adjusted Net Loss of $34.5
million, or $0.14 per diluted share, for the first quarter
2017.
Adjusted EBITDA (a non-GAAP measure) for the first quarter 2018
was $171.9 million compared with $170.7 million for the first
quarter 2017, primarily due to an increase in average realized
prices and an increase in oil equivalent production in the Permian
Basin and Haynesville/Cotton Valley, which were partially offset by
the loss of Adjusted EBITDA from the Pinedale Divestiture, which
closed in September 2017, and increases in general and
administrative and lease operating expenses.
The definitions and reconciliations of Adjusted Net Income
(Loss) and Adjusted EBITDA to net income (loss) are provided within
Non-GAAP Measures at the end of this release.
Production
Oil equivalent production was 11.7 MMboe for the first quarter
2018 compared with 13.1 MMboe for the first quarter 2017, an 11%
decrease. Oil and condensate production increased 6%, while natural
gas and NGL production decreased 17% and 33%, respectively. First
quarter 2018 equivalent production was positively impacted by
increased drilling and completion activity in the Permian Basin and
Haynesville/Cotton Valley. The increase was offset by lower
production resulting from decreased drilling activity in the
Williston Basin and the loss of 3.5 MMboe of production in Pinedale
as a result of the Pinedale Divestiture.
Operating Expenses
During the first quarter 2018, lease operating expense (LOE) was
$72.5 million, or $6.18 per Boe, an increase of 17% compared with
the first quarter 2017, primarily due to the loss of lower LOE cost
per Boe production in Pinedale as a result of the Pinedale
Divestiture. Excluding the Pinedale Divestiture, LOE per Boe was
down 2% in the quarter, primarily due to a decrease in the Permian
Basin, which was driven by lower LOE cost per Boe production from
recent horizontal well completions offsetting higher LOE cost per
Boe production associated with low volume vertical wells obtained
in the 2017 Permian Basin acquisition.
During the first quarter 2018, Adjusted transportation and
processing (T&P) costs (a non-GAAP measure) were $46.7 million,
or $3.98 per Boe, a decrease of 26% compared with the first quarter
2017, primarily due to the loss of higher per Boe T&P cost
production in Pinedale as a result of the Pinedale Divestiture.
Excluding the Pinedale Divestiture, Adjusted transportation and
processing costs per Boe were down 28% in the quarter, primarily
due to decreased T&P costs per Boe in the Haynesville/Cotton
Valley, driven by an increase in production that increased
utilization of the Company's firm transportation commitments on
interstate pipelines. The definition and reconciliation of Adjusted
transportation and processing costs to the transportation and
processing costs presented in QEP's statement of operations are
provided within Non-GAAP Measures at the end of this release.
During the first quarter 2018, production and property taxes
were $28.9 million, or $2.47 per Boe, an increase of 11% compared
with the first quarter 2017. The increase in production and
property taxes was primarily due to an overall increase in average
field-level oil equivalent prices in the Permian Basin and an
increase in production volumes in Haynesville/Cotton Valley during
the first quarter 2018. The increase was partially offset by the
Pinedale Divestiture.
During the first quarter 2018, general and administrative
expense was $60.1 million, or $5.13 per Boe, an increase of 79%
compared with the first quarter 2017. The increase in the first
quarter 2018 was primarily due to an increase in termination
benefits and severance expenses associated with our Strategic
Initiatives. In addition to these restructuring costs, QEP
recognized an increase in share-based compensation and changes in
the mark-to-market value of the Deferred Compensation Wrap Plan, an
increase in outside services, an increase in labor, benefits and
employee expenses and an increase in legal expenses.
Capital Investment
Capital investment, excluding property acquisitions, was $418.8
million (on an accrual basis) for the first quarter 2018, compared
with $214.3 million for the first quarter 2017. Approximately
$400.2 million of the capital expenditures was related to the
drilling, completion and equipping of wells and $17.9 million was
related to infrastructure investment. The increase in capital
expenditures was primarily related to increased drilling and
completion activity in the Permian Basin and Haynesville/Cotton
Valley and significant improvements in drilling and completion
efficiency primarily in the Permian Basin, which have accelerated
the well delivery schedule for 2018.
During the first quarter 2018, QEP acquired various oil and gas
properties, which primarily included proved and unproved leasehold
acreage in the Permian Basin, for an aggregate purchase price of
$36.2 million, subject to customary post-closing adjustments. Of
the $36.2 million, $35.7 million was related to acquisitions of
additional oil and gas interests in certain properties in the 2017
acquisition of oil and gas properties in the Permian Basin (the
2017 Permian Basin Acquisition) on substantially the same terms and
conditions as the 2017 Permian Basin Acquisition.
Share Repurchase
During March 2018, the Company repurchased and retired 5,621,540
shares at a weighted average price of $9.37 per share, for $52.8
million. Additionally, the Company entered into trades to
repurchase an additional 592,310 shares at a weighted average price
of $9.37 per share, for $5.6 million in late March 2018. The shares
purchased in late March 2018 were settled and retired in April
2018.
Asset Divestitures
QEP closed on the sale of several non-core assets for total
proceeds of approximately $33.3 million during the first quarter
2018. In addition, in April 2018, the Company has provided data for
potential buyers to evaluate for the divestiture of the Company's
Williston and Uinta Basin assets.
Liquidity
As of March 31, 2018, QEP had $385.0 million of borrowings
outstanding and $1.0 million in letters of credit outstanding under
its revolving credit facility. The Company estimates, that as of
March 31, 2018, it could incur additional indebtedness of
approximately $315.0 million and be in compliance with the
covenants contained in its revolving credit facility.
2018 Strategic Initiatives
In February 2018, QEP’s Board of Directors unanimously approved
certain Strategic Initiatives, summarized below, to transition the
Company to a pure-play Permian Basin company and to address the
significant discount to net asset value reflected in the Company's
share price.
- Divest of the Company’s Williston and Uinta basin assets
- Market remaining non-Permian assets, including the
Haynesville/Cotton Valley, in the second half of 2018
- Use proceeds from asset sales to fund Permian Basin development
program until the program reaches operating cash flow neutrality in
2019, reduce debt and return cash to shareholders through share
repurchases
- Authorized a $1.25 billion share repurchase program(1)
____________________________(1) Subject
to available liquidity, market conditions and proceeds from asset
sales.
Updated 2018 Guidance
The Company’s updated guidance assumes no additional property
acquisitions or divestitures, other than those executed in the
first quarter 2018, and assumes that QEP will elect to reject
ethane from its produced gas for the entire year where QEP has the
right to make such an election, except in the Permian Basin where
processing economics support ethane recovery.
QEP's updated full year 2018 guidance is detailed below.
Rig Count
- Permian Basin (average of four and one-half rigs) - expected to
drop to four rigs in May 2018 for balance of year
- Williston Basin (average of one-quarter rig) - rig released on
April 9, 2018
- Haynesville/Cotton Valley (average of one-half rig) - rig
expected to be released mid-May 2018
Wells Put on Production:
- Company: approximately 120 net operated wells
- Permian Basin: approximately 104 net operated wells
Refracs:
- Approximately 28 net refracs between the Williston Basin and
Haynesville/Cotton
Slide 7 in the April 2018 Investor Presentation provides
additional details on QEP's 2018 Guidance.
|
2018 Guidance |
|
2018 |
|
2018 |
|
Previous Forecast |
|
Current Forecast |
Oil & condensate
production (MMbbl) |
21.0 - 22.5 |
21.5 - 23.0 |
Gas production
(Bcf) |
132.0 - 143.0 |
135.0 - 145.0 |
NGL
production (MMbbl) |
4.7 - 5.2 |
4.25 - 4.75 |
Total oil
equivalent production (MMboe) |
47.7 - 51.5 |
48.3 - 51.9 |
|
|
|
Lease operating and
transportation expense (per Boe)(1) |
$9.00 - $10.00 |
$9.00 - $10.00 |
Depletion, depreciation
and amortization (per Boe) |
$17.50 - $18.50 |
$17.00 - $18.00 |
Production and property
taxes (% of field-level revenue) |
|
8.5 |
% |
|
|
|
|
|
|
8.5 |
% |
(in millions) |
General and
administrative expense(2) |
$185 - $205 |
$195 - $215 |
|
|
|
Capital investment
(excluding property acquisitions) |
|
|
Drilling,
Completion and Equip(3) |
$965 - $1,065 |
$1,000 - $1,100 |
Infrastructure |
|
$50 |
|
|
$60 |
Corporate |
|
$10 |
|
|
$10 |
Total
capital investment (excluding property acquisitions) |
$1,025 - $1,125 |
$1,070 - $1,170 |
|
|
|
|
|
|
|
|
(1) |
|
Lease
operating and transportation expense (per Boe) is calculated using
adjusted transportation and processing costs, a non-GAAP measure.
Refer to Non-GAAP Measures at the end of this release. |
|
(2) |
|
General and
administrative expense includes approximately $25.0 million of
non-cash share-based compensation expense and approximately $20.0
million of estimated termination benefits and retention program
expense. |
|
(3) |
|
Approximately 70% of the planned capital investment is focused on
projects in the Permian Basin. Drilling, Completion and Equip
includes approximately $20.0 million of non-operated well
completion costs. |
|
|
|
|
|
Updated 2018 Quarterly Production
Guidance |
|
1Q 2018 |
|
1Q 2018 |
|
|
2Q 2018 |
|
3Q 2018 |
|
4Q 2018 |
|
2018 |
QEP
Resources |
Forecast |
|
Actuals |
|
Current Forecast |
Oil & condensate
production (MMbbl) |
4.5 -
4.7 |
|
5.0 |
|
|
5.4 -
5.7 |
|
5.7 -
6.3 |
|
5.4 -
5.9 |
|
21.5 -
23.0 |
Gas production
(Bcf) |
31.7 -
33.6 |
|
35.1 |
|
|
35.2 -
37.3 |
|
35.6 -
39.0 |
|
29.1 -
33.6 |
|
135.0
- 145.0 |
NGL production
(MMbbl) |
1.0 - 1.1 |
|
0.9 |
|
|
1.1 - 1.2 |
|
1.2 - 1.3 |
|
1.1 - 1.3 |
|
4.25 - 4.75 |
Total oil equivalent production (MMboe) |
10.8 -
11.4 |
|
11.7 |
|
|
12.4 - 13.1 |
|
12.8 - 14.3 |
|
11.3 - 12.8 |
|
48.3 - 51.9 |
Total
wells put on production (net) |
20 |
|
35 |
|
|
45 |
|
24 |
|
16 |
|
120 |
Total
refracs put on production (net) |
14 |
|
14 |
|
|
10 |
|
4 |
|
— |
|
28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian
Basin |
|
|
|
|
|
|
|
|
|
|
|
|
Oil & condensate
production (MMbbl) |
2.0 -
2.1 |
|
2.2 |
|
|
2.7 -
2.8 |
|
3.0 -
3.3 |
|
3.1 -
3.4 |
|
11.0 -
11.7 |
Gas production
(Bcf) |
1.6 -
1.8 |
|
1.9 |
|
|
1.9 -
2.1 |
|
2.4 -
2.6 |
|
2.5 -
2.7 |
|
8.7 -
9.3 |
NGL
production (MMbbl) |
0.30 - 0.35 |
|
0.3 |
|
|
0.35 - 0.40 |
|
0.40 - 0.45 |
|
0.42 - 0.47 |
|
1.48 - 1.63 |
Permian
Basin equivalent production (MMboe) |
2.6 -
2.8 |
|
2.8 |
|
|
3.4 - 3.6 |
|
3.8 - 4.2 |
|
3.9 - 4.3 |
|
13.9 -14.8 |
Permian
Basin wells put on production (net) |
18 |
|
31 |
|
|
33 |
|
24 |
|
16 |
|
104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations Summary
|
|
|
|
|
|
|
|
|
|
|
Permian Basin |
|
Williston Basin |
|
Haynesville/CottonValley |
|
Uinta Basin |
|
|
As of March 31, 2018 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Well
Progress |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
20 |
|
|
19.6 |
|
|
1 |
|
|
0.5 |
|
|
2 |
|
|
2.0 |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At total depth - under
drilling rig |
|
8 |
|
|
7.7 |
|
|
5 |
|
|
5.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Waiting to be
completed |
|
15 |
|
|
14.4 |
|
|
2 |
|
|
2.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Undergoing
completion |
|
6 |
|
|
6.0 |
|
|
2 |
|
|
2.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Completed, awaiting
production |
|
9 |
|
|
9.0 |
|
|
1 |
|
|
1.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Waiting
on completion |
|
38 |
|
|
37.1 |
|
|
10 |
|
|
10.0 |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Put on
production(1) |
|
31 |
|
|
31.0 |
|
|
— |
|
|
— |
|
|
2 |
|
|
2.0 |
|
|
2 |
|
|
2.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Total wells
put on production during the quarter ended March 31,
2018. |
Permian Basin
Permian Basin net oil equivalent production averaged
approximately 30.9 Mboed (89% liquids) during the first quarter
2018, a record for the Company in the basin, and an 11% increase
compared with the fourth quarter 2017 and a 101% increase compared
with the first quarter 2017.
In the first quarter 2018, the Company put on production 31
gross-operated horizontal wells, 13 more than originally forecast,
in the first quarter 2018 (average working interest 100%) in two,
one-half-mile wide drilling spacing units (DSU), one DSU with nine
and the other DSU with 22 wells. While the majority of the wells
were still in the process of cleaning up at the end of the quarter,
early performance suggests the wells are performing at or above
expectations, based on their respective well densities. The greater
than planned delivery of wells in the first quarter 2018 was due to
decreased drilling times and better than forecast completion
efficiency. Since entering the Permian Basin in 2014, the Company
has achieved an almost three-fold increase in the number of frac
stages completed per frac crew per month, with the two crews
working for QEP averaging over 355 stages per crew per month during
the first quarter 2018. The Company has also reduced drill times
(spud to total depth) by more than 25% over the past twelve
months.
At the end of the first quarter 2018, the Company had 20
gross-operated horizontal wells in process of being drilled (of
which nine had surface casing set, but had no drilling rig
present), eight horizontal wells at total depth under drilling rigs
(average working interest 96%), 15 horizontal wells waiting to
be completed (average working interest 96%), six horizontal
wells undergoing completion (average working interest 100%), and
nine fully completed horizontal wells awaiting first production,
which were part of a tank "pressure wall" (average working interest
100%).
Current QEP-operated drilled and completed authorization for
expenditure (AFE) well costs for the Permian Basin are detailed on
slide 24 of the April 2018 Investor Presentation.
At the end of the first quarter 2018, the Company had six
operated rigs in the Permian Basin.
Slides 9-16 in the April 2018 Investor Presentation depict QEP's
acreage and activity in the Permian Basin.
Williston Basin
Williston Basin net oil equivalent production averaged
approximately 41.4 Mboed (85% liquids) during the first quarter
2018, a 15% decrease compared with the fourth quarter 2017 and a
23% decrease compared with the first quarter 2017.
The Company completed and returned to production seven
gross-operated refracs on South Antelope (average working interest
97%) during the first quarter 2018. None of the seven refracs had
reached peak oil rates by the end of the quarter. The Company also
plans to complete eight additional refracs on South Antelope during
the remainder of 2018. Current average gross QEP-operated Williston
Basin refrac costs are approximately $4.8 million per well.
At the end of the first quarter 2018, the Company had one
gross-operated horizontal well being drilled (working interest
50%), five horizontal wells at total depth under drilling rigs
(average working interest 100%), two gross-operated horizontal
wells waiting to be completed (average working interest 100%), two
horizontal wells undergoing completion (average working interest
100%), and one fully completed horizontal well awaiting first
production (working interest 100%), all on South Antelope.
Current QEP-operated drilled and completed AFE well costs for
the Williston Basin are detailed on slide 24 of the April 2018
Investor Presentation.
At the end of the first quarter 2018, the Company had one
operated rig in the Williston Basin on South Antelope.
Slides 17-19 in the April 2018 Investor Presentation depict
QEP's acreage and activity in the Williston Basin.
Haynesville/Cotton Valley
Haynesville/Cotton Valley net gas equivalent production averaged
approximately 286.0 MMcfed (47.7 Mboed) during the first quarter
2018, a 9% increase compared with the fourth quarter 2017 and a
110% increase compared with the first quarter 2017.
The Company put on production two gross operated wells during
the first quarter 2018 (average working interest 100%). The first
well put on production in the quarter had a peak 24-hour IP rate of
44.4 MMcfed (100% gas) with a lateral length of 9,725 feet. The
second well put on production in the quarter had a peak 24-hour IP
rate of 38.3 MMcfed (100% gas) with a lateral length of 9,947
feet.
During the quarter the Company completed and returned to
production seven QEP-operated refracs, with an average incremental
24-hour rate increase of 14.6 MMcfed (average working interest
99%). The Company expects to refrac approximately six additional
net operated wells during 2018.
Current average gross QEP-operated Haynesville refrac costs are
approximately $4.9 million per well.
At the end of the first quarter, the Company had one operated
rig in Haynesville/Cotton Valley and two gross horizontal wells in
the process of being drilled (average working interest 100%).
Slides 20-21 in the April 2018 Investor Presentation depict
QEP's acreage and activity in Haynesville/Cotton Valley.
Uinta Basin
Uinta Basin net production averaged approximately 53.6 MMcfed
(8.9 Mboed) (23% liquids) during the first quarter 2018, a 2%
decrease compared with the fourth quarter 2017 and an 18% decrease
compared with the first quarter 2017.
During the first quarter 2018, the Company put on production two
gross operated vertical wells (average working interest 100%).
At the end of the first quarter, the Company had no drilling
rigs in the Uinta Basin.
Slide 22 in the April 2018 Investor Presentation depicts QEP's
acreage and activity in the Uinta Basin.
First Quarter 2018 Results Conference Call
QEP’s management will discuss first quarter 2018 results in a
conference call on Thursday, April 26, 2018, beginning at 9:00
a.m. EDT. The conference call can be accessed at www.qepres.com.
You may also participate in the conference call by dialing (877)
869-3847 in the U.S. or Canada and (201) 689-8261 for international
calls. A replay of the teleconference will be available on the
website immediately after the call through May 26, 2018, or by
dialing (877) 660-6853 in the U.S. or Canada and (201) 612-7415 for
international calls, and then entering the conference ID #
13678506. In addition, QEP’s slides for the first quarter 2018,
with updated maps showing QEP’s leasehold and current activity for
key operating areas discussed in this release, can be found on the
Company’s website.
About QEP Resources, Inc.
QEP Resources, Inc. (NYSE:QEP) is an independent crude oil and
natural gas exploration and production company with operations in
two regions of the United States: the Northern Region (primarily in
North Dakota and Utah) and the Southern Region (primarily in Texas
and Louisiana). For more information, visit QEP's website at:
www.qepres.com.
Forward-Looking Statements
This release includes forward-looking statements within the
meaning of Section 27(a) of the Securities Act of 1933, as amended,
and Section 21(e) of the Securities Exchange Act of 1934, as
amended. Forward-looking statements can be identified by words such
as “anticipates,” “believes,” “forecasts,” “plans,” “estimates,”
“expects,” “should,” “will” or other similar expressions. Such
statements are based on management’s current expectations,
estimates and projections, which are subject to a wide range of
uncertainties and business risks. These forward-looking statements
include statements regarding: planned Strategic Initiatives;
planned asset divestitures and timing of such divestitures; use of
proceeds from sale of assets; factors impacting the timing and
amount of purchases under QEP’s share repurchase program; becoming
a pure-play Permian Basin company; utilization of QEP’s
tank-style completion methodology and anticipated benefits from
this methodology; reaching operating cash flow neutrality in 2019;
the number and location of drilling rigs to be deployed, wells to
be put on production and refracs; increased number of wells to be
completed; forecast production amounts and growth and related
assumptions; forecast lease operating and transportation expense,
depletion, depreciation and amortization expense, general and
administrative expense, non-cash share-based compensation expense,
termination benefits and retention program expense, production and
property taxes, and capital investment for 2018 and related
assumptions for such guidance; allocation of capital expenditures;
quarterly production guidance and assumptions for such guidance;
plans regarding ethane rejection and recovery; and the amount of
additional indebtedness QEP could incur and be compliance with loan
covenants. Actual results may differ materially from those included
in the forward-looking statements due to a number of factors,
including, but not limited to: timing and amount of asset
divestitures and share repurchases; changes in oil, gas and NGL
prices; liquidity constraints, including those resulting from the
cost or unavailability of financing due to debt and equity capital
and credit market conditions, changes in QEP’s credit rating, QEP’s
compliance with loan covenants, the increasing credit pressure on
QEP’s industry or demands for cash collateral by counterparties to
derivative and other contracts; market conditions; global
geopolitical and macroeconomic factors; the activities of
the Organization of Petroleum Exporting Countries; general
economic conditions, including interest rates; changes in local,
regional, national and global demand for natural oil, gas and NGL;
impact of new laws and regulations, including the use of hydraulic
fracture stimulation; impact of U.S. dollar exchange rates on oil,
gas and NGL prices; elimination of federal income tax deductions
for oil and gas exploration and development; guidance for
implementation of the Tax Cuts and Jobs Act; actual proceeds from
asset sales; actions of activist shareholders; tariffs on products
QEP uses in its operations or sells; drilling results; shortages of
oilfield equipment, services and personnel; the availability of
storage and refining capacity; operating risks such as unexpected
drilling conditions; transportation constraints; weather
conditions; changes in maintenance, service and construction costs;
permitting delays; outcome of contingencies such as legal
proceedings; inadequate supplies of water and/or lack of water
disposal sources; and the other risks discussed in the Company’s
periodic filings with the Securities and Exchange Commission,
including the Risk Factors section of the Company’s Annual Report
on Form 10-K for the year ended December 31, 2017. QEP
undertakes no obligation to publicly correct or update the
forward-looking statements in this news release, in other
documents, or on the website to reflect future events or
circumstances. All such statements are expressly qualified by this
cautionary statement.
Contact |
Investors/Media: |
William I. Kent,
IRC |
Director, Investor
Relations |
303-405-6665 |
|
QEP
RESOURCES, INC. |
CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS |
(Unaudited) |
|
Three Months Ended |
|
March 31, |
|
2018 |
|
2017 |
REVENUES |
(in millions, except per share amounts) |
Oil and
condensate, gas and NGL sales |
$ |
409.8 |
|
|
$ |
385.2 |
|
Other
revenue |
5.0 |
|
|
4.0 |
|
Purchased
oil and gas sales |
14.1 |
|
|
30.9 |
|
Total
Revenues |
428.9 |
|
|
420.1 |
|
OPERATING
EXPENSES |
|
|
|
Purchased
oil and gas expense |
15.5 |
|
|
29.4 |
|
Lease
operating expense |
72.5 |
|
|
69.2 |
|
Transportation and processing costs |
34.0 |
|
|
70.2 |
|
Gathering
and other expense |
2.8 |
|
|
1.5 |
|
General
and administrative |
60.1 |
|
|
33.6 |
|
Production and property taxes |
28.9 |
|
|
29.1 |
|
Depreciation, depletion and amortization |
196.5 |
|
|
191.8 |
|
Exploration expenses |
— |
|
|
0.4 |
|
Impairment |
0.7 |
|
|
0.1 |
|
Total
Operating Expenses |
411.0 |
|
|
425.3 |
|
Net gain (loss) from
asset sales |
3.5 |
|
|
— |
|
OPERATING
INCOME (LOSS) |
21.4 |
|
|
(5.2 |
) |
Realized and unrealized
gains (losses) on derivative contracts |
(53.2 |
) |
|
160.9 |
|
Interest and other
income (expense) |
(0.7 |
) |
|
0.6 |
|
Interest expense |
(35.0 |
) |
|
(33.8 |
) |
INCOME
(LOSS) BEFORE INCOME TAXES |
(67.5 |
) |
|
122.5 |
|
Income tax (provision)
benefit |
13.9 |
|
|
(45.6 |
) |
NET
INCOME (LOSS) |
$ |
(53.6 |
) |
|
$ |
76.9 |
|
|
|
|
|
Earnings (loss) per
common share |
|
|
|
Basic |
$ |
(0.22 |
) |
|
$ |
0.32 |
|
Diluted |
$ |
(0.22 |
) |
|
$ |
0.32 |
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
Used in
basic calculation |
240.9 |
|
|
240.2 |
|
Used in
diluted calculation |
240.9 |
|
|
240.3 |
|
Dividends per common
share |
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
QEP
RESOURCES, INC. |
CONDENSED CONSOLIDATED BALANCE SHEETS |
(Unaudited) |
|
March 31, 2018 |
|
December 31, 2017 |
ASSETS |
(in millions) |
Current Assets |
|
|
|
Cash and
cash equivalents |
$ |
— |
|
|
$ |
— |
|
Accounts
receivable, net |
130.2 |
|
|
142.1 |
|
Income
tax receivable |
4.7 |
|
|
4.9 |
|
Fair
value of derivative contracts |
3.2 |
|
|
3.4 |
|
Hydrocarbon inventories, at lower of average cost or net realizable
value |
2.1 |
|
|
3.6 |
|
Prepaid
expenses |
9.4 |
|
|
10.7 |
|
Other
current assets |
0.2 |
|
|
0.7 |
|
Total
Current Assets |
149.8 |
|
|
165.4 |
|
Property, Plant and
Equipment (successful efforts method for oil and gas
properties) |
|
|
|
Proved
properties |
12,676.1 |
|
|
12,470.9 |
|
Unproved
properties |
1,073.7 |
|
|
1,095.8 |
|
Gathering
and other |
383.4 |
|
|
319.7 |
|
Materials
and supplies |
38.4 |
|
|
37.8 |
|
Total
Property, Plant and Equipment |
14,171.6 |
|
|
13,924.2 |
|
Less Accumulated
Depreciation, Depletion and Amortization |
|
|
|
Exploration and production |
6,660.8 |
|
|
6,642.9 |
|
Gathering
and other |
130.6 |
|
|
124.3 |
|
Total
Accumulated Depreciation, Depletion and Amortization |
6,791.4 |
|
|
6,767.2 |
|
Net
Property, Plant and Equipment |
7,380.2 |
|
|
7,157.0 |
|
Fair value of
derivative contracts |
4.5 |
|
|
0.1 |
|
Other noncurrent
assets |
74.1 |
|
|
72.3 |
|
TOTAL
ASSETS |
$ |
7,608.6 |
|
|
$ |
7,394.8 |
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
Current
Liabilities |
|
|
|
Checks
outstanding in excess of cash balances |
$ |
19.8 |
|
|
$ |
44.0 |
|
Accounts
payable and accrued expenses |
400.9 |
|
|
364.6 |
|
Production and property taxes |
31.9 |
|
|
31.6 |
|
Interest
payable |
33.4 |
|
|
26.0 |
|
Fair
value of derivative contracts |
116.9 |
|
|
103.6 |
|
Asset
retirement obligations |
10.1 |
|
|
7.5 |
|
Total
Current Liabilities |
613.0 |
|
|
577.3 |
|
Long-term debt |
2,458.1 |
|
|
2,160.8 |
|
Deferred income
taxes |
504.0 |
|
|
518.0 |
|
Asset retirement
obligations |
200.4 |
|
|
206.6 |
|
Fair value of
derivative contracts |
32.8 |
|
|
31.8 |
|
Other long-term
liabilities |
103.6 |
|
|
102.4 |
|
Commitments and
contingencies |
|
|
|
EQUITY |
|
|
|
Common
stock – par value $0.01 per share; 500.0 million shares
authorized; 240.3 million and 243.0 million shares issued,
respectively |
2.4 |
|
|
2.4 |
|
Treasury
stock – 2.6 million and 2.0 million shares, respectively |
(39.5 |
) |
|
(34.2 |
) |
Additional paid-in capital |
1,408.0 |
|
|
1,398.2 |
|
Retained
earnings |
2,336.3 |
|
|
2,442.6 |
|
Accumulated other comprehensive income (loss) |
(10.5 |
) |
|
(11.1 |
) |
Total
Common Shareholders' Equity |
3,696.7 |
|
|
3,797.9 |
|
TOTAL
LIABILITIES AND EQUITY |
$ |
7,608.6 |
|
|
$ |
7,394.8 |
|
|
|
|
|
|
|
|
|
|
QEP
RESOURCES, INC. |
CONDENSED CONSOLIDATED STATEMENTS OF CASH
FLOWS |
(Unaudited) |
|
Three Months Ended |
|
March 31, |
|
2018 |
|
2017 |
OPERATING
ACTIVITIES |
(in millions) |
Net income (loss) |
$ |
(53.6 |
) |
|
$ |
76.9 |
|
Adjustments to
reconcile net income (loss) to net cash provided by (used in)
operating activities: |
|
|
|
Depreciation, depletion and amortization |
196.5 |
|
|
191.8 |
|
Deferred
income taxes (benefit) |
(14.1 |
) |
|
45.6 |
|
Impairment |
0.7 |
|
|
0.1 |
|
Share-based compensation |
11.2 |
|
|
6.0 |
|
Amortization of debt issuance costs and discounts |
1.3 |
|
|
1.5 |
|
Bargain
purchase gain from acquisition |
— |
|
|
0.4 |
|
Net
(gain) loss from asset sales |
(3.5 |
) |
|
— |
|
Unrealized (gains) losses on marketable securities |
0.1 |
|
|
(0.8 |
) |
Unrealized (gains) losses on derivative contracts |
10.0 |
|
|
(177.3 |
) |
Changes in operating
assets and liabilities |
11.8 |
|
|
5.7 |
|
Net Cash
Provided by (Used in) Operating Activities |
160.4 |
|
|
149.9 |
|
INVESTING
ACTIVITIES |
|
|
|
Property
acquisitions |
(36.2 |
) |
|
(68.2 |
) |
Property, plant and
equipment, including exploratory well expense |
(370.7 |
) |
|
(177.3 |
) |
Proceeds from
disposition of assets |
33.3 |
|
|
0.2 |
|
Net Cash
Provided by (Used in) Investing Activities |
(373.6 |
) |
|
(245.3 |
) |
FINANCING
ACTIVITIES |
|
|
|
Checks outstanding in
excess of cash balances |
(24.2 |
) |
|
(3.1 |
) |
Proceeds from credit
facility |
1,068.5 |
|
|
— |
|
Repayments of credit
facility |
(772.5 |
) |
|
— |
|
Common stock
repurchased and retired |
(52.8 |
) |
|
— |
|
Treasury stock
repurchases |
(4.7 |
) |
|
(6.4 |
) |
Net Cash
Provided by (Used in) Financing Activities |
214.3 |
|
|
(9.5 |
) |
Change in cash, cash
equivalents and restricted cash |
1.1 |
|
|
(104.9 |
) |
Beginning cash, cash
equivalents and restricted cash |
23.4 |
|
|
465.4 |
|
Ending cash, cash
equivalents and restricted cash |
$ |
24.5 |
|
|
$ |
360.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production by Region |
|
|
Three Months Ended March 31, |
|
|
2018 |
|
2017 |
|
Change |
|
|
(in Mboe) |
Northern
Region |
|
|
|
|
|
|
Williston
Basin |
|
3,729.7 |
|
|
4,834.0 |
|
|
(23 |
)% |
Pinedale |
|
0.1 |
|
|
3,514.9 |
|
|
(100 |
)% |
Uinta
Basin |
|
804.5 |
|
|
968.3 |
|
|
(17 |
)% |
Other
Northern |
|
105.4 |
|
|
330.4 |
|
|
(68 |
)% |
Total
Northern Region |
|
4,639.7 |
|
|
9,647.6 |
|
|
(52 |
)% |
Southern
Region |
|
|
|
|
|
|
|
Permian
Basin |
|
2,782.9 |
|
|
1,389.5 |
|
|
100 |
% |
Haynesville/Cotton Valley |
|
4,290.5 |
|
|
2,046.7 |
|
|
110 |
% |
Other
Southern |
|
11.5 |
|
|
6.5 |
|
|
77 |
% |
Total
Southern Region |
|
7,084.9 |
|
|
3,442.7 |
|
|
106 |
% |
Total production |
|
11,724.6 |
|
|
13,090.3 |
|
|
(10 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
Three Months Ended March 31, |
|
|
2018 |
|
2017 |
|
Change |
Oil
(Mbbl) |
|
4,974.0 |
|
|
4,682.7 |
|
|
6 |
% |
Gas
(Bcf) |
|
35.1 |
|
|
42.3 |
|
|
(17 |
)% |
NGL
(Mbbl) |
|
904.4 |
|
|
1,355.4 |
|
|
(33 |
)% |
Total
production (Mboe) |
|
11,724.6 |
|
|
13,090.3 |
|
|
(10 |
)% |
Average
daily production (Mboe) |
|
130.3 |
|
|
145.4 |
|
|
(10 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices |
|
|
Three Months Ended March 31, |
|
|
2018 |
|
2017 |
|
Change |
Oil (per
bbl) |
|
|
|
|
|
|
Average
field-level price |
|
$ |
60.45 |
|
|
$ |
47.35 |
|
|
|
Commodity
derivative impact |
|
(8.91 |
) |
|
(0.43 |
) |
|
|
Net
realized price |
|
$ |
51.54 |
|
|
$ |
46.92 |
|
|
10 |
% |
Gas (per
Mcf) |
|
|
|
|
|
|
Average
field-level price |
|
$ |
2.91 |
|
|
$ |
3.18 |
|
|
|
Commodity
derivative impact |
|
0.03 |
|
|
(0.34 |
) |
|
|
Net
realized price |
|
$ |
2.94 |
|
|
$ |
2.84 |
|
|
4 |
% |
NGL (per
bbl) |
|
|
|
|
|
|
Average
field-level price |
|
$ |
21.99 |
|
|
$ |
21.36 |
|
|
|
Commodity
derivative impact |
|
— |
|
|
— |
|
|
|
Net
realized price |
|
$ |
21.99 |
|
|
$ |
21.36 |
|
|
3 |
% |
Average net
equivalent price (per Boe) |
|
|
|
|
|
|
Average
field-level price |
|
$ |
36.04 |
|
|
$ |
29.43 |
|
|
|
Commodity
derivative impact |
|
(3.70 |
) |
|
(1.24 |
) |
|
|
Net
realized price |
|
$ |
32.34 |
|
|
$ |
28.19 |
|
|
15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
Three Months Ended March 31, |
|
|
2018 |
|
2017 |
|
Change |
|
|
(in millions) |
Lease operating
expense |
|
$ |
72.5 |
|
|
$ |
69.2 |
|
|
5 |
% |
Adjusted transportation
and processing costs(1) |
|
46.7 |
|
|
70.2 |
|
|
(33 |
)% |
Production and property
taxes |
|
28.9 |
|
|
29.1 |
|
|
(1 |
)% |
|
|
$ |
148.1 |
|
|
$ |
168.5 |
|
|
(12 |
)% |
|
|
|
|
|
|
|
|
|
(per Boe) |
Lease operating
expense |
|
$ |
6.18 |
|
|
$ |
5.29 |
|
|
17 |
% |
Adjusted transportation
and processing costs(1) |
|
3.98 |
|
|
5.36 |
|
|
(26 |
)% |
Production and property
taxes |
|
2.47 |
|
|
2.23 |
|
|
11 |
% |
Total production
costs |
|
$ |
12.63 |
|
|
$ |
12.88 |
|
|
(2 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Adjusted
transportation and processing costs is a non-GAAP measure. The
definition and reconciliation of adjusted transportation and
processing costs to transportation and processing costs, as
presented, are provided within Non-GAAP Measures at the end of this
release. |
QEP RESOURCES,
INC.NON-GAAP
MEASURES(Unaudited)
Adjusted EBITDA
This release contains references to the non-GAAP measure of
Adjusted EBITDA. Management defines Adjusted EBITDA as earnings
before interest, income taxes, depreciation, depletion and
amortization (EBITDA), adjusted to exclude changes in fair value of
derivative contracts, exploration expenses, gains and losses from
asset sales, impairment and certain other items. Management uses
Adjusted EBITDA to evaluate QEP's financial performance and trends,
make operating decisions and allocate resources. Management
believes the measure is useful supplemental information for
investors because it eliminates the impact of certain nonrecurring,
non-cash and/or other items that management does not consider as
indicative of QEP's performance from period to period. QEP's
Adjusted EBITDA may be determined or calculated differently than
similarly titled measures of other companies in our industry, which
would reduce the usefulness of this non-GAAP financial measure when
comparing our performance to that of other companies.
Below is a reconciliation of Net Income (Loss) (a GAAP measure)
to Adjusted EBITDA. This non-GAAP measure should be considered by
the reader in addition to, but not instead of, the financial
statements prepared in accordance with GAAP.
|
|
|
|
|
Three Months Ended |
|
|
March 31, |
|
|
2018 |
|
2017 |
|
|
(in millions) |
Net income (loss) |
|
$ |
(53.6 |
) |
|
$ |
76.9 |
|
Interest expense |
|
35.0 |
|
|
33.8 |
|
Interest and other
(income) expense |
|
0.7 |
|
|
(0.6 |
) |
Income tax provision
(benefit) |
|
(13.9 |
) |
|
45.6 |
|
Depreciation, depletion
and amortization |
|
196.5 |
|
|
191.8 |
|
Unrealized (gains)
losses on derivative contracts |
|
10.0 |
|
|
(177.3 |
) |
Exploration
expenses |
|
— |
|
|
0.4 |
|
Net (gain) loss from
asset sales |
|
(3.5 |
) |
|
— |
|
Impairment |
|
0.7 |
|
|
0.1 |
|
Adjusted
EBITDA |
|
$ |
171.9 |
|
|
$ |
170.7 |
|
Adjusted Net Income (Loss)
This release contains references to the non-GAAP measure of
Adjusted Net Income (Loss). Management defines Adjusted Net Income
(Loss) as earnings excluding gains and losses from asset sales,
unrealized gains and losses on derivative contracts, asset
impairments and certain other items. Management uses Adjusted Net
Income (Loss) to evaluate QEP’s financial performance and trends,
make operating decisions, and allocate resources. Management
believes the measure is useful supplemental information for
investors because it eliminates the impact of certain nonrecurring,
non-cash and/or other items that management does not consider as
indicative of QEP’s performance from period to period. QEP’s
Adjusted Net Income (Loss) may be determined or calculated
differently than similarly titled measures of other companies in
our industry, which would reduce the usefulness of this non-GAAP
financial measure when comparing our performance to that of other
companies.
Below is a reconciliation of Net Income (Loss) (a GAAP measure)
to Adjusted Net Income (Loss). This non-GAAP measure should be
considered by the reader in addition to, but not instead of, the
financial statements prepared in accordance with GAAP.
|
|
|
|
|
Three Months Ended March 31, |
|
|
2018 |
|
2017 |
|
|
(in millions, except earnings per share) |
Net income (loss) |
|
$ |
(53.6 |
) |
|
$ |
76.9 |
|
Adjustments to net
income (loss) |
|
|
|
|
Unrealized (gains) losses on derivative contracts |
|
10.0 |
|
|
(177.3 |
) |
Income
taxes on unrealized (gains) losses on derivative contracts(1) |
|
(2.1 |
) |
|
65.8 |
|
Net
(gain) loss from asset sales |
|
(3.5 |
) |
|
— |
|
Income
taxes on net (gain) loss from asset sales(1) |
|
0.7 |
|
|
— |
|
Impairment |
|
0.7 |
|
|
0.1 |
|
Income
taxes on impairment(1) |
|
(0.1 |
) |
|
— |
|
Total after tax
adjustments to net income |
|
5.7 |
|
|
(111.4 |
) |
Adjusted Net Income
(Loss) |
|
$ |
(47.9 |
) |
|
$ |
(34.5 |
) |
|
|
|
|
|
Earnings (Loss) per
Common Share |
|
|
|
|
Diluted
earnings per share |
|
$ |
(0.22 |
) |
|
$ |
0.32 |
|
Diluted
after-tax adjustments to net income (loss) per share |
|
0.02 |
|
|
(0.46 |
) |
Diluted
Adjusted Net Income per share |
|
$ |
(0.20 |
) |
|
$ |
(0.14 |
) |
|
|
|
|
|
Weighted-average common
shares outstanding |
|
|
|
|
Diluted |
|
240.9 |
|
|
240.3 |
|
|
|
|
|
|
(1) |
|
Income tax
impact of adjustments is calculated using QEP’s statutory rate of
20.7% and 37.1% for the three months ended March 31, 2018 and
2017, respectively. |
Adjusted Transportation and Processing
Costs
This release contains references to the non-GAAP measure of
adjusted transportation and processing costs. Management defines
adjusted transportation and processing costs as transportation and
processing costs presented on the Condensed Consolidated Statements
of Operations and transportation and processing costs that are
included as part of "Oil and condensate, gas and NGL sales" on the
Condensed Consolidated Statements of Operations. These costs are
added together to reflect the total operating costs associated with
QEP's production. Management believes that this non-GAAP measure is
useful supplemental information for investors as it reflects the
total production costs required to operate the wells for the period
and is a more comparable measure to the operating costs of its
peers.
Below is a reconciliation of adjusted transportation and
processing costs to transportation and processing costs as
presented on the Condensed Consolidated Statements of Operations (a
GAAP measure). This non-GAAP measure should be considered by the
reader in addition to but not instead of, the financial statements
prepared in accordance with GAAP.
|
|
|
|
|
Three Months Ended March 31, |
|
|
2018 |
|
2017 |
|
Change |
|
|
(in millions) |
Adjusted transportation
and processing costs |
|
$ |
46.7 |
|
|
$ |
70.2 |
|
|
$ |
(23.5 |
) |
Transportation and
processing costs deducted from oil and condensate, gas and NGL
sales |
|
(12.7 |
) |
|
— |
|
|
(12.7 |
) |
Transportation and processing costs, as presented |
|
$ |
34.0 |
|
|
$ |
70.2 |
|
|
$ |
(36.2 |
) |
|
|
|
|
|
|
|
|
|
(per Boe) |
Adjusted transportation
and processing costs |
|
$ |
3.98 |
|
|
$ |
5.36 |
|
|
$ |
(1.38 |
) |
Transportation and
processing costs deducted from oil and condensate, gas and NGL
sales |
|
(1.08 |
) |
|
— |
|
|
(1.08 |
) |
Transportation and processing costs, as presented |
|
$ |
2.90 |
|
|
$ |
5.36 |
|
|
$ |
(2.46 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The following tables present QEP's volumes and average prices
for its open derivative positions as of April 20, 2018:
|
Production Commodity Derivative
Swaps |
Year |
|
Index |
|
Total Volumes |
|
Average Swap Priceper Unit |
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
(bbls |
) |
|
|
($/bbl |
) |
2018
(April through December) |
|
NYMEX
WTI |
|
12.7 |
|
|
$ |
52.48 |
|
2019 |
|
NYMEX
WTI |
|
9.5 |
|
|
$ |
52.66 |
|
Gas
sales |
|
|
|
(MMBtu |
) |
|
|
($/MMBtu |
) |
2018 (May
through December) |
|
NYMEX
HH |
|
71.7 |
|
|
$ |
3.00 |
|
2018
(July through December) |
|
NYMEX
HH |
|
1.8 |
|
|
$ |
3.01 |
|
2019 |
|
NYMEX
HH |
|
43.8 |
|
|
$ |
2.86 |
|
|
|
|
|
|
|
|
|
|
|
|
Production Commodity Derivative Basis
Swaps |
Year |
|
Index Less Differential |
|
Index |
|
Total Volumes |
|
Weighted-AverageDifferential |
|
|
|
|
|
|
(in millions) |
|
|
Oil
sales |
|
|
|
|
|
(bbls |
) |
|
|
($/bbl |
) |
2018
(April through December) |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
5.5 |
|
|
$ |
(1.06 |
) |
2018
(July through December) |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
0.9 |
|
|
$ |
(0.71 |
) |
2019 |
|
NYMEX
WTI |
|
Argus
WTI Midland |
|
4.7 |
|
|
$ |
(0.77 |
) |
Gas
sales |
|
|
|
|
|
(MMBtu |
) |
|
|
($/MMBtu |
) |
2018 (May
through December) |
|
NYMEX
HH |
|
IFNPCR |
|
4.9 |
|
|
$ |
(0.16 |
) |
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